U.S. patent number 7,274,996 [Application Number 10/967,737] was granted by the patent office on 2007-09-25 for method and system for monitoring fluid flow.
This patent grant is currently assigned to Genscape Intangible Holding, Inc.. Invention is credited to Deirdre Alphenaar, John Carroll Hill, Sterling Lapinski.
United States Patent |
7,274,996 |
Lapinski , et al. |
September 25, 2007 |
Method and system for monitoring fluid flow
Abstract
A method and system for monitoring fluid flow, such as fluid
flow through pipelines or similar conduits for delivering natural
gas, crude oil, and other similar liquid or gas energy commodities,
relies on the measurement of acoustic waves generated by the fluid,
thus allowing for monitoring of the flow rate without direct access
to the fluid. Furthermore, the method and system allows for
estimation of the operational dynamics of components or facilities
of the production, transportation, storage, and distribution
systems for the energy commodities.
Inventors: |
Lapinski; Sterling (Louisville,
KY), Hill; John Carroll (Pewee Valley, KY), Alphenaar;
Deirdre (Louisville, KY) |
Assignee: |
Genscape Intangible Holding,
Inc. (Louisville, KY)
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Family
ID: |
34526751 |
Appl.
No.: |
10/967,737 |
Filed: |
October 18, 2004 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20050086012 A1 |
Apr 21, 2005 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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60512649 |
Oct 20, 2003 |
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Current U.S.
Class: |
702/48;
702/54 |
Current CPC
Class: |
G01F
1/666 (20130101) |
Current International
Class: |
G01F
17/00 (20060101); G06F 19/00 (20060101) |
Field of
Search: |
;702/1-14,46-50,54
;166/53,249 ;340/606 ;73/861.25 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Robert P. Evans et al., Flow Rate Measurements Using Flow-Induced
Pipe Vibration, Journal of Fluid Engineering, Mar. 2004, pp.
280-285, vol. 126. cited by other.
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Primary Examiner: Bui; Bryan
Assistant Examiner: Taylor; Victor J.
Attorney, Agent or Firm: Stites & Harbison, PLLC Nagle,
Jr.; David W.
Parent Case Text
CROSS-REFERENCE TO RELATED APPLICATIONS
The present application claims priority to U.S. Provisional
Application Ser. No. 60/512,649 filed Oct. 20, 2003, the entire
disclosure of which is incorporated herein by reference.
Claims
What is claimed is:
1. A method for providing information relating to fluid flow rate
through a conduit to a remote third party, comprising the steps of:
positioning one or more sound transducers in proximity to and
external to said conduit, each said sound transducer generating a
signal representative of acoustic waves generated by the fluid flow
through said conduit; collecting said signals from said one or more
sound transducers on a substantially continuous basis; processing
said signals to determine the flow rate through the conduit; and
communicating information relating to the flow rate to said remote
third party.
2. The method as recited in claim 1, in which signals generated by
said one or more sound transducers are received and collected by a
local monitoring device and then transmitted from the local
monitoring device to a remote central processing facility for
processing said signals to determine the flow rate through the
conduit.
3. The method as recited in claim 1, in which said one or more
sound transducers are near, but not in physical contact with, said
conduit.
4. The method as recited in claim 1, in which communicating
information relating to the flow rate to said remote third party is
accomplished through export of such information to an Internet web
site accessible by said third party.
5. A method for monitoring fluid flow through a conduit and
communicating a flow rate to a third party, comprising the steps
of: positioning one or more sound transducers in proximity to and
external to said conduit, each said sound transducer generating a
signal representative of a measured amplitude of acoustic waves
generated by the fluid flow through said conduit; receiving such
acoustic signals and processing the signals into digitized data
representative of the measured amplitude on a substantially
continuous basis; performing a computational analysis on the
digitized data to determine the flow rate through said conduit
based on the measured amplitude; and communicating the flow rate to
said third party.
6. The method as recited in claim 5, wherein the receiving and
processing of the signals into digitized data representative of the
measured amplitude is carried out by a monitoring device in general
proximity to the sound transducers.
7. The method as recited in claim 6, and further comprising the
step of transmitting the digitized data from the monitoring device
to a central processing facility for performing the computational
analysis on the digitized data to determine the flow rate through
said conduit.
8. The method as recited in claim 6, wherein the monitoring device
includes one or more amplification and filtration circuits for
amplifying the signal from each sound transducer and for removing
extraneous noise prior to the processing of the signals into
digitized data representative of the measured amplitude.
9. The method as recited in claim 6, in which the monitoring device
is powered by a battery that is continuously recharged by a solar
panel array.
10. The method as recited in claim 7, in which transmitting the
digitized data is accomplished by a radio frequency transceiver
associated with the monitoring device.
11. The method as recited in claim 5, in which communicating the
flow rate to said third party is accomplished through export of the
flow rate to an Internet web site accessible by said third
party.
12. A method for monitoring fluid flow through a conduit and
communicating a flow rate to a third party, comprising the steps
of: detecting an amplitude of acoustic waves generated by fluid
flow through said conduit; generating a signal representative of
the detected amplitude; transmitting the signal representative of
the detected amplitude to a monitoring device on a substantially
continuous basis; processing the signal into digitized data
representative of the measured amplitude; performing a
computational analysis on the digitized data to determine the flow
rate through said conduit based on the measured amplitude; and
communicating the flow rate to said third party.
13. The method as recited in claim 12, in which communicating the
flow rate to said third party is accomplished through export of the
flow rate to an Internet web site accessible by said third
party.
14. A method for estimating operational dynamics of a facility,
comprising the steps of: positioning at least one monitoring device
in proximity to and external to each of a number of selected
conduits of the facility, each such monitoring device including at
least one sound transducer for generating a signal representative
of acoustic waves generated by the flow of an energy commodity
through each selected conduit; each monitoring device receiving
such signals on a substantially continuous basis and processing the
signals into digitized data representative of the acoustic waves;
processing the digitized data to determine a flow rate of the
energy commodity through each selected conduit; estimating the
operational dynamics of the facility based on the determined flow
rates; and communicating information related to the operational
dynamics of the facility to a third party.
15. The method as recited in claim 14, in which each monitoring
device transmits digitized data representative of the acoustic
waves to a remote central processing facility for processing the
digitized data to determine the flow rate of the energy commodity
through each selected conduit and estimating the operational
dynamics of the facility based on the determined flow rates.
16. The method as recited in claim 14, in which communicating
information related to the operational dynamics of the facility to
a third party is accomplished through export of such information to
an Internet web site accessible by said third party.
17. A method for estimating fluid flow through a conduit,
comprising the steps of: positioning one or more sound transducers
in proximity to and external to said conduit, each said sound
transducer generating a signal representative of a measured
amplitude of acoustic waves generated by the fluid flow through
said conduit; monitoring actual fluid flow through the conduit;
comparing the measured amplitudes to the actual fluid flow to
develop a mathematical relationship between the measured amplitude
and the actual fluid flow; and using the developed mathematical
relationship for future estimates of fluid flow through the conduit
or another conduit having similar physical characteristics.
18. A method for providing information relating to fluid flow rate
through a conduit to a remote third party in substantially
real-time, comprising the steps of: positioning one or more sound
transducers in proximity to and external to said conduit, each said
sound transducer generating a signal representative of acoustic
waves generated by the fluid flow through said conduit; collecting
said signals from said one or more sound transducers on a
substantially continuous basis; processing said signals to
determine the flow rate through the conduit; and communicating
information relating to the flow rate to said remote third party on
a substantially real-time basis.
19. The method as recited in claim 18, in which signals generated
by said one or more sound transducers are received and collected by
a local monitoring device and then transmitted from the local
monitoring device to a remote central processing facility for
processing said signals to determine the flow rate through the
conduit.
20. The method as recited in claim 18, in which said one or more
sound transducers are near, but not in physical contact with, said
conduit.
21. The method as recited in claim 18, in which communicating
information relating to the flow rate to said remote third party on
a substantially real-time basis is accomplished through export of
such information to an Internet web site accessible by said third
party.
Description
BACKGROUND OF THE INVENTION
The present invention relates to a method and system for monitoring
fluid flow, such as fluid flow through pipelines or similar
conduits for delivering natural gas, crude oil, and other liquid or
gas energy commodities. The method and system relies on the
measurement of acoustic waves generated by the fluid, thus allowing
for monitoring of the flow rate without direct access to the
fluid.
Natural gas, crude oil, and other similar liquid or gas energy
commodities comprise a multi-billion dollar economic market. These
commodities are bought and sold by many parties, and as with any
traded market, information about the traded commodities is very
valuable to market participants. Specifically, the operations of
the various components and facilities of the production,
transportation, storage, and distribution systems for each of these
commodities can have significant impacts on the price and
availability of these commodities, making information about said
operations valuable. Furthermore, such information generally is not
disclosed publicly by the various component owners or operators,
and access to said information is therefore limited.
It would therefore be desirable to provide a method and system for
monitoring fluid flow through pipelines or similar conduits for
delivering natural gas, crude oil, and other similar liquid or gas
energy commodities, such that information about such commodities
can be accumulated and communicated to market participants and
other interested parties.
SUMMARY OF THE INVENTION
The present invention is a method and system for monitoring fluid
flow, such as fluid flow through pipelines or similar conduits for
delivering natural gas, crude oil, and other similar liquid or gas
energy commodities. The method and system relies on the measurement
of acoustic waves generated by the fluid from a location external
to the conduit in which the fluid is flowing, thus allowing for
monitoring of the flow rate without direct access to the fluid.
Furthermore, the method and system of the present invention allows
for estimation of the operational dynamics of components or
facilities of the production, transportation, storage, and
distribution systems for the energy commodities.
A general property of fluids (whether compressible or
incompressible) flowing through pipes or similar conduits is that
they produce acoustic waves, i.e., sound or vibration. The sound
produced by the flow of natural gas or other energy commodity can
be characterized by its amplitude and frequency. In this regard,
the amplitude and frequency are generally directly related to the
velocity of the fluid through the conduit, and thus the flow rate
of the fluid. Therefore, a sound transducer or similar sensor can
be positioned to detect the acoustic waves emanating from a
particular conduit caused by fluid flow through that conduit, and
by recording and analyzing the acoustic waves, the flow rate
through the conduit can be estimated. In this regard, the flow rate
is commonly expressed as a volumetric flow rate, i.e.,
characterized as the volume of fluid passing by a designated point
over a predetermined time period.
One or more sound transducers are positioned in proximity to a
pipeline such that acoustic waves can be reliably detected. Each
sound transducer detects the amplitude and/or frequency of the
acoustic waves generated by the gas flow through the pipeline and
generates a signal representative of that measurement. The signal
generated by each sound transducer is transmitted to an
above-ground monitoring device in general proximity to the sound
transducers and the monitored pipeline. The monitoring device
houses the various electronic equipment necessary to process the
signals from the sound transducers and transmit collected data to a
central processing facility. Specifically, the monitoring device is
programmed such that it periodically or continuously collects data
from the sound transducers, processes that data into a form
suitable for transmission, and transmits the data to a remote
central processing facility.
At the central processing facility, a computational analysis is
performed by a digital computer program to determine the flow rate
of the fluid through the monitored pipeline. Furthermore, for any
particular facility or other component of the production,
transportation, storage, and/or distribution system for which all,
or most of, the connected pipelines are monitored in accordance
with the present invention, through a simple summing of the
volumetric flow rates on each pipeline, the output or production of
the facility can be determined. Then, information associated with
the production or output of one or more facilities or components
can then be communicated to third parties. This information may
include not only the measured flow rates or output estimates, but
also historical data, capacity estimates, or similar data that
places the measured flow rates or output estimates in context for
market participants and other interested parties. It is
contemplated and preferred that such communication to third parties
be through export of the data to an access-controlled Internet web
site, which end users can access through a common Internet browser
program.
DESCRIPTION OF THE DRAWINGS
FIG. 1 is a schematic representation of a natural gas system;
FIG. 2 is a schematic representation of an exemplary implementation
of the method and system of the present invention;
FIG. 3 is a perspective view of an exemplary monitoring device made
in accordance with the present invention;
FIG. 4 is a functional block diagram of the sound transducers and
the monitoring device in an exemplary implementation of the method
and system of the present invention;
FIG. 5 is a functional block diagram of the communication
components and the central processing facility in an exemplary
implementation of the method and system of the present
invention;
FIG. 6 illustrates the monitoring of a storage facility to which
three pipelines are connected in accordance with the method and
system of the present invention;
FIG. 7 is a graph illustrating the measured signal amplitudes from
a sound transducer positioned adjacent a particular conduit for a
defined time period, such that a best fit equation can be developed
for subsequent measurements of flow rate through this particular
conduit; and
FIG. 8 is a graph illustrating the measured signal amplitudes from
a sound transducer positioned adjacent another particular conduit
for a defined time period, such that a best fit equation can be
developed for subsequent measurements of flow rate through this
particular conduit.
DETAILED DESCRIPTION OF THE INVENTION
The present invention is a method and system for monitoring fluid
flow, such as fluid flow through pipelines or similar conduits for
delivering natural gas, crude oil, and other similar liquid or gas
energy commodities. The method and system relies on the measurement
of acoustic waves generated by the fluid from a location external
to the conduit in which the fluid is flowing, thus allowing for
monitoring of the flow rate without direct access to the fluid.
Furthermore, the method and system of the present invention allows
for estimation of the production or output of components or
facilities of the production, transportation, storage, and
distribution systems for the energy commodities. For purposes of
the present application, the production, output, and/or other
measure of the flow of an energy commodity through or relative to a
component or facility may be referred to as the "operational
dynamics" of that component or facility.
To accomplish this, it is first important to recognize that the
production, transportation, storage and distribution of liquid or
gas energy commodities occurs most often through networks of
pipelines. These pipelines connect various system components, such
as production wells, storage facilities of various types, and
distribution networks comprised of ever-smaller pipelines.
For example, with respect to the natural gas industry and as
illustrated in FIG. 1, natural gas is located and collected by
production companies from geographically dispersed wells, which are
generally indicated by reference numerals 10A, 10B, and 10C in FIG.
1. The natural gas collected from these wells is delivered through
a network of pipelines (or similar conduits) 12A, 12B, 12C to a
primary trunk line 14. From such a trunk line 14, the natural gas
is delivered to storage facilities 16, which are typically depleted
natural gas fields, salt domes, or similar underground structures;
and/or to local distribution companies 18, which in turn, sell and
deliver the natural gas to industrial, commercial, and residential
end users for ultimate consumption.
In any event, a general property of fluids flowing through pipes or
similar conduits is that they produce acoustic waves, i.e., sound
or vibration. The sound produced by the flow of natural gas or
other energy commodity can be characterized by its amplitude and
frequency. In this regard, the amplitude and frequency are
generally directly related to the velocity of the flow, and thus
the flow rate of the fluid. Furthermore, for compressible fluids,
the amplitude and frequency are also generally directly related to
the density of the fluid, and thus the volumetric flow rate of the
fluid. Therefore, a sound transducer or similar sensor can be
positioned to detect the acoustic waves emanating from a particular
conduit caused by fluid flow through that conduit. By recording and
analyzing the acoustic waves, the flow rate through the conduit can
be estimated. As mentioned above, the flow rate is commonly
expressed as a volumetric flow rate, i.e., characterized as the
volume of fluid passing by a designated point over a predetermined
time period.
FIG. 2 is a schematic representation of an exemplary implementation
of the method and system of the present invention. In this example,
an underground pipeline 32 is monitored.
Accordingly, one or more sound transducers 34a, 34b . . . 34n (also
referred to as acoustic sensors or gas sensors) are positioned in
proximity to the pipeline 32, that is, in physical contact with the
pipeline 32 or sufficiently close to said pipeline 32 such that
acoustic waves can be reliably detected. In this regard, multiple
sensors are often preferable to provide multiple measurements at
locations along the pipeline 32, which can then be averaged to
reduce error. It is contemplated that various commercially
available transducers or sensors could be used to achieve the
objectives of the present invention. For example, one preferred
sound transducer suitable for the purposes of the present invention
is a seismic, high-sensitivity accelerometer manufactured and
distributed by PCB Piezotronics, Inc. of Depew, New York as Model
No. 393B12.
As mentioned above, the sound transducers 34a, 34b . . . 34n are
positioned in contact with the pipeline 32 or sufficiently close to
said pipeline 32 such that acoustic waves can be reliably detected.
For example, many commercially available transducers supply
mounting magnets for direct attachment of the transducers to a
pipeline or similar conduit. Alternatively, when no such magnet is
provided, each sound transducer 34a, 34b . . . 34n may be mounted
to the pipeline 32 by attaching a substantially flat magnet to the
transducer using an adhesive material, with the magnet then being
used to secure the sound transducer 34a, 34b . . . 34n to the
pipeline 32. In this regard, each sound transducer 34a, 34b . . .
34n could be provided with a curved magnet that better matches the
contour of the pipeline to which it is secured. Furthermore,
various adhesives could be used to secure each sound transducer
34a, 34b . . . 34n directly to the pipeline 32. Finally, in
circumstances where physical access to the pipeline 32 is not
possible or is impractical, the sound transducers 34a, 34b . . .
34n may be mounted on a bracket or similar frame that maintains the
position of the sound transducers 34a, 34b . . . 34n relative to
the pipeline 32 without necessarily contacting the pipeline 32.
In any event, in this example, each sound transducer 34 detects the
amplitude of the acoustic waves generated by the gas flow through
the pipeline 32 and generates a signal representative of that
amplitude. The signal generated by each sound transducer 34a, 34b .
. . 34n is transmitted via an appropriate cable 36a, 36b . . . 36n
to an above-ground monitoring device 30, which is preferably
"local" in that it is located in general proximity to the sound
transducers 34a, 34b . . . 34n and the pipeline 32. As illustrated
in FIG. 3, an exemplary monitoring device 30 includes a
substantially weatherproof enclosure 31 that is secured to a post
and houses the various electronic equipment necessary to process
the signals from the sound transducers 34a, 34b . . . 34n and to
transmit collected data to a central processing facility, as is
further described below.
FIG. 4 is a functional block diagram of the sound transducers 34a,
34b . . . 34n and the monitoring device 30. As shown, the
monitoring device 30 is programmed such that it periodically or
continuously collects data from the sound transducers 34a, 34b . .
. 34n, processes that data into a form suitable for transmission,
and transmits the data to a remote central processing facility
where various computational analyses are performed on the data to
determine the flow rate of natural gas or other energy commodity
through the monitored pipeline.
Specifically, the output voltage of the first sound transducer 34a
is applied to a amplification and filtration circuit 40a, which has
a dual function. One function of the amplification and filtration
circuit 40a is to amplify the relatively small output voltage of
the sound transducer 34a to a level that will be suitable as an
input to an analog-to-digital converter. The secondary function of
the circuit 40a is to serve as a filter, removing extraneous noise
from the output voltage of each sound transducer 34a. Similarly,
the output voltage of the second sound transducer 34b is applied to
another amplification and filtration circuit 40b to amplify the
voltage and remove extraneous noise, and so on. The specific design
of the amplification and filtration circuits 40a, 40b . . . 40n is
immaterial, and various amplification and filtration circuits could
be designed to achieve the dual objectives of amplifying the
voltage and removing extraneous noise by one of ordinary skill in
the art.
After the amplification and filtration of the respective signals,
the output voltages are then applied to the inputs of an analog
multiplexer (MUX) 42. Furthermore, although not shown in FIG. 4, it
may be advisable to apply the output voltages of the respective
amplification and filtration circuits 40a, 40b . . . 40n to the
inputs of respective sample-and-hold amplifiers before such output
voltages are applied to the MUX 42 in order to avoid time-skew in
the subsequent conversion of these signals from analog to digital
form. Sample-and-hold amplifiers are generally known in the art,
and any conventional means for performing the sample-and-hold
function maybe incorporated into the present invention as
contemplated herein.
From the MUX 42, the signals are separately passed through an
analog-to-digital (A/D) converter 44. Which of the multiple signals
is passed through to the analog-to-digital converter 44 at any
given time is determined by a control logic associated with a
microprocessor 50. The converted data, representative of the
amplitude of the measured acoustic waves and now in digital form,
is stored in memory associated with the microprocessor 50. The
outputted signal from the microprocessor 50 is then transmitted to
one or both of a radio frequency (RF) transceiver 58 with
associated transmission antenna 60 (which is also shown in FIG. 3)
and a landline network 62 for subsequent transmission of the signal
to a central processing facility.
Finally, the individual electronic components of the monitoring
device 30 are preferably powered by a battery 70 that may be
continuously recharged by a solar panel array 72 (which is also
shown in FIG. 3).
FIG. 5 is a functional block diagram of the communication
components and the central processing facility in this exemplary
implementation of the method and system of the present invention.
These components are not installed in the field with the monitoring
device 30, but rather are located at some remote location.
Specifically, the outputted data from the microprocessor 50
depicted in FIG. 3 is transmitted to the central processing
facility via one or both of a radio frequency (RF) transceiver 58
with associated transmission antenna 60 and a landline network 62.
A receiving antenna 100 or similar communication component, which
is in range of one or more monitoring devices 30 in the field,
receives this data, which is representative of the acoustic
measurements. The receiving antenna 100 is operably connected to an
analog or digital communications network 102 which transmits the
signal to the central processing facility 110. Such transmission
may be carried out, for example, by a satellite link 104, a
microwave link 106, and/or a fiber optic link 108, although other
data transmission means may certainly be used without departing
from the spirit and scope of the present invention.
At the central processing facility 110, a computational analysis,
as will be described in detail below, is performed by a digital
computer program 112 to determine the flow rate of the gas (or
similar fluid) through the pipeline 32. Furthermore, for any
particular natural gas facility or other component of the
production, transportation, storage, and/or distribution system for
which all, or most of, the connected pipelines are monitored in
accordance with the present invention, through a simple summing of
the flow rates on each pipeline, the natural gas production of the
facility can be determined. Then, information associated with the
production or output of one or more facilities or components can
then be communicated to third parties. This information may include
not only the measured flow rates or output estimates, but also
historical data, capacity estimates, or similar data that places
the measured flow rates or output estimates in context for market
participants and other interested parties. It is contemplated and
preferred that such communication to third parties be through
export of the data to an access-controlled Internet web site 114,
which end users can access through a common Internet browser
program 116, such as Microsoft Internet Explorer.RTM.. Of course,
communication of information and data to third parties may also be
accomplished through a wide variety of other known communications
media without departing from the spirit and scope of the present
invention.
As an additional refinement, the communications channel from the
microprocessor 50 of the local monitoring device 30 to the central
processing facility 110 may be bi-directional so that the
information maintained and stored in the microprocessor 50 may be
sent out on a scheduled basis or may be polled. Furthermore,
through bi-directional communications, the microprocessor 50 is
remotely re-programmable.
With respect to the computational analysis mentioned above, the
relationship of the measured acoustic waves through a conduit to
the flow rate is somewhat mathematically complex because the
acoustic waves may result not only from fluid flow, but also from
the interaction of the fluid with mechanical components of the
pipeline, including compressors, gas flow meters, flow and pressure
regulators, control valves and/or similar equipment connected to
and/or external to the pipeline. However, in circumstances where
the interaction of such components or equipment is independent of
changing conditions in the fluid itself, the amplitude of the
acoustic waves generally increases with increases in the flow rate.
For further details and discussion of the sources of noise and the
levels of noise produced in gas pipelines, reference is made to
Nelson, D. A.; and Cooper, B. A.: Reduced-Noise Gas Flow Design
Guide for NASA Glenn Research Center, Proceedings of InterNoise 99,
the International Congress on Noise Control Engineering. Institute
of Noise Control Engineering (Washington, DC, 1999), a publication
which is incorporated herein by reference.
Accordingly, by selecting an appropriate location along a pipeline,
a location where interaction of the fluid with other components or
equipment is minimal, through comparison of measured acoustic waves
to known flow rates, a mathematical relationship suitable for
prediction of flow rate can be developed.
For example, FIG. 7 is a graph illustrating the measured signal
amplitudes from a sound transducer positioned adjacent a particular
conduit for more than a 105-hour time period. During this time
period, the actual gas flow was also monitored. Applying a linear
regression analysis to this data set, a mathematical relationship
was developed, specifically: Estimated Flow (Mcfh)=[K (Signal
Amplitude)+C]* 1000 (1) where Mcfh refers to thousand cubic feet
per hour, and where K=1.6159 and C=0.5158/ Of course, this
mathematical relationship is somewhat unique to the particular
conduit. Indeed, the size of the conduit, the characteristics of
the specific sound transducers, and environmental conditions may
all have an effect on the relationship between measured acoustic
waves and flow rate.
For another example, FIG. 8 is a graph illustrating the measured
amplitudes from a sound transducer positioned adjacent another
conduit for a 180-hour time period. Again, during this time period,
the actual gas flow was also monitored. Applying a linear
regression analysis to this data set, a mathematical relationship
was developed, specifically: Estimated Flow (mcfh)=K (Signal
Amplitude).sup.C (2) where K=2100 and C=0.30
This mathematical relationship is also unique to the particular
conduit and environmental conditions. Nonetheless, by developing
"best fit" equations for various conduits in various settings, as
the above examples demonstrate, when a new conduit is to be
monitored, an appropriate equation can be selected based on the
size of the conduit, environmental conditions, etc. Furthermore,
through data accumulation and analysis, it is expected that
additional correlations may be deduced, such as the relationship of
the constants K and C to: (1) certain identifiable characteristics
of the conduit, such as internal diameter of the conduit and wall
thickness of the conduit; (2) characteristics of the fluid, such as
temperature, pressure, velocity, etc.; and (3) characteristics
associated with different types of nearby mechanical noise sources,
such as compressors and control valves. In his regard, for
estimates of noise resulting from many such characteristics,
reference is again made to Nelson, D. A.; and Cooper, B. A.:
Reduced-Noise Gas Flow Design Guide for NASA Glenn Research Center,
Proceedings of InterNoise 99, the International Congress on Noise
Control Engineering. Institute of Noise Control Engineering
(Washington, D.C., 1999), a publication which has been incorporated
herein by reference.
In any event, once the appropriate mathematical relationship has
been developed, a particular conduit can be monitored in
substantially real-time. Once the digitized data associated with
the monitoring of that particular conduit is received at the
central processing facility, the necessary computational analysis
is carried out, preferably by a digital computer program, to
determine the flow rate of the gas (or similar fluid) through the
conduit.
As mentioned above, through such computations, the method and
system of the present invention allows for estimation of the
operational dynamics of components or facilities of the production,
transportation, storage, and distribution systems for the energy
commodities. For example, in the natural gas industry, storage
facilities receive and store gas collected by production companies
during periods of lower usage (i.e., the summer months) and then
distribute stored gas to local distribution companies during
periods of high usage (i.e., the winter months), as generally
described above with reference to FIG. 1. Of course, gas is
transported into and out of such storage facilities through a
number of pipelines. Through an estimation of the amount of gas
flowing through each pipeline as described above, coupled with a
knowledge of the direction of flow through each pipeline, through a
simple summing of the flow rates on each pipeline, the net
injection or withdrawal of gas for a particular storage facility
can be determined. Then, as also described above, this estimate can
be communicated to third parties through an access-controlled
Internet web site or otherwise.
FIG. 7 illustrates such an estimate of the output of a storage
facility 16 to which three pipelines 32, 132, 232 are connected.
Each such pipeline 32, 132, 232 is monitored by a package of one or
more sound transducers 34, 134, 234 and associated monitoring
devices 30, 130, 230. Data collected and processed by each
monitoring device 30, 130, 230 is transmitted via a satellite link
104 to a central processing facility 110, where, through a simple
summing of the computed flow rates on each pipeline 32, 132, 232,
the net injection or withdrawal of gas for the storage facility 16
can be determined.
With respect to the direction of flow through each pipeline
associated with a facility, various techniques can be used to
deduce the direction of flow. For example, pipeline networks at
storage facilities includes similar mechanical components and
structures, with the function of these components and structures
often being dependent on the direction of flow through the
pipeline. Accordingly, an evaluation of the physical layout of the
pipeline networks may provide some indication of the direction of
flow. Furthermore, an analysis of the measured acoustic waves may
provide an indication of the direction of flow in that certain
mechanical components may be activated when gas flow is in a
certain direction (e.g., a compressor for injection of gas into the
storage facility). For another example, the knowledge of the
seasonal operation of the storage facility, as mentioned above, may
be used to deduce the direction of flow. Regardless of the
technique used, the net injection or withdrawal of gas for a
particular storage facility can thus be determined.
One of ordinary skill in the art will recognize that additional
embodiments and/or implementations are possible without departing
from the teachings of the present invention or the scope of the
claims which follow. This detailed description, and particularly
the specific details of the exemplary implementation disclosed
therein, is given primarily for clarity of understanding, and no
unnecessary limitations are to be understood therefrom, for
modifications will become obvious to those skilled in the art upon
reading this disclosure and may be made without departing from the
spirit or scope of the claimed invention.
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